Systems and methods for distributed interferometric acoustic monitoring

ABSTRACT

This disclosure relates in general to a method and system for acoustic monitoring using a fibre optic cable. More specifically, but not by way of limitation, embodiments of the present invention provide for using an optical fiber as a distributed interferometer that may be used to monitor a conduit, wellbore or reservoir. In certain aspects, the distributed interferometric monitoring provides for accurate detection of acoustic occurrences along the fibre optic cable and these acoustic occurrences may include fluid flow in a pipeline or wellbore, processes taking place in a wellbore or pipeline, fracturing, gravel packing, production logging and/or the like.

This patent application is a divisional from U.S. patent applicationSer. No. 11/934,551 filed Nov. 2, 2007 which is incorporated byreference herein in its entirety.

BACKGROUND

This disclosure relates in general to a method and system for monitoringa conduit, a wellbore or a reservoir associated with hydrocarbonproduction or transportation and/or carbon dioxide sequestration. Morespecifically, but not by way of limitation, embodiments of the presentinvention provide for using an optical fiber as a distributedinterferometer that may be used to monitor the conduit, wellbore orreservoir.

A wide variety of techniques have previously been used to monitorreservoirs, wellbores and/or pipes containing hydrocarbons, such assub-sea pipelines, transportation pipelines and/or the like. Monitoringof wellbores may often occur during completion and/or production stagesand monitoring may comprise monitoring reservoir conditions, estimatingquantities of hydrocarbons (oil and gas), monitoring treatment of thewellbore—which may include monitoring treatment fluids applied to thewellbore, the effects of the treatment fluids and/or the like—monitoringoperation of downhole devices in the wellbores, determining conditionsin the wellbore, determining condition of the wellbore itself and/ordownhole devices, monitoring hydrocarbon production, monitoringcompletion processes, monitoring stimulation processes, monitoring theformation surrounding the wellbore, monitoring flow of hydrocarbonsthrough a conduit and/or the like.

Reservoir monitoring may involve determining downhole parameters atvarious locations in a producing wellbore over an extended period oftime. To provide for this type of monitoring in a wellbore or the like,wireline tools may be deployed into the wellbore to obtain measurements.Such use of wireline tools is invasive, may affect other operationsbeing performed in the wellbore and/or operations it that might bedesirable to perform in the wellbore when the wireline tool is deployed.

In general, wireline monitoring involves transporting the wireline toolsto the wellsite, conveying the tools into the wellbores, shutting downthe production, making measurements over extended periods of time andprocessing the resultant data. Use of wireline tools may be expensive,cause production delay and because the wireline tools may, in certaincircumstances, have to be removed from the wellbore for other wellboreprocedures to occur, may not provide for detecting/analyzing continuousdata from the wellbore. Similarly, with conduits containinghydrocarbons, periodic testing along/through the conduit as to thecondition of the conduit, analysis of any material in and/or flowing inthe conduit and/or analysis of the hydrocarbons in the conduit may alsobe invasive, expensive, cause production/transportation delay, onlyprovide for sporadic monitoring, only provide for disjointed monitoringof specific locations along the conduit and/or the like.

With regard to the production stages of a well, a wide range ofintervention production logging tools exist which may be lowered into awell and measure flow conditions at a known location. These tools may bemoved through the well to provide multi-point measurements. These toolsare not ideally suited to monitoring simultaneous events at multiplelocations or for long period deployments. In addition, it may bedifficult to log below wellbore architecture like valves, packers orpumps. Also the very fact of installing such a tool may changeconditions such that the measured results are not representative ofthose when the tool is not present.

With regard to the wellbore, monitoring of sand in the wellbore may beof high important for certain types of wellbores, since the productionof sand in the wellbore may have detrimental effects on production ofhydrocarbons from the wellbore. Sand may be considered to be any type ofparticulate matter in the wellbore. Sand may cause such detrimentaleffects as clogging well lines, adversely affecting pump operation,causing corrosion and/or erosion to pipes and associated equipmentand/or the like. As such, sand monitoring along the wellbore may benecessary so that steps may be taken to counter its possible adverseeffects.

Additionally, with regard to wellbore processes, gravel packing may be aprocess that it is desirable to monitor and to manage. The gravelpacking process involves pumping a gravel slurry along a length of thewellbore and then allowing the gravel to drop-out filling the wellborearound a sand screen disposed in the wellbore. Typically, the lowersection of the wellbore may be filled from heel to toe (often referredto as the Alpha wave) then the upper section from toe to heel (oftenreferred to as the Beta wave).

A full understanding of how and where gravel deposition is occurring inreal-time may provide the knowledge required to optimize the gravelplacement process. Downhole monitoring of the treatment may show whengravel deposition along the screen is not progressing as desired, witheither areas of low gravel concentration (possibly leading to voids) orvery high concentrations (possibly leading to premature bridging). Whenproblems with the pack deposition are identified, treatment pumpingparameters may be altered to help rectify the situation. Pump rate,fluid viscosity or gravel concentration may all be managed if real-timemonitoring is occurring to improve the gravel deposition. Downholehardware may also be customized to allow for altered flow paths based oninformation about the gravel bed development.

In addition to monitoring many other processes and procedures in awellbore, such as gas lift monitoring, flow obstacles, device operation,stimulation processes etc., it may also be desirable to monitortransportation of hydrocarbons through pipelines for flow assurancepurposes and/or the like. Further, with increased attention to anddevelopment of carbon dioxide sequestration in subsurface locations, apermanent or semi-permanent type sensor for monitoring thetransportation and subsurface sequestration of carbon dioxide is alsodesirable.

SUMMARY

This disclosure relates in general to a method and system for monitoringa pipeline, a wellbore or a reservoir associated with hydrocarbonproduction or transportation and/or carbon dioxide sequestration. Morespecifically, but not by way of limitation, embodiments of the presentinvention provide for using an optical fiber as a distributedinterferometer that may be used to monitor the conduit, wellbore orreservoir. In certain aspects of the present invention, the sensitivityof the distributed interferometer is configured to provide for acousticmonitoring of the reservoir, wellbore and/or pipeline.

Embodiments of the present invention provide for developing coherentRayleigh noise (“CRN”) in a fiber optic sensor and processing thedeveloped CRN in the fiber optic sensor to provide for monitoring awellbore, reservoir or conduit. CRN may be generated in the fiber opticsensor by injecting a coherent beam of electromagnetic radiation intothe fiber optic sensor, wherein the coherent beam and the fiber opticsensor are configured to provide for interference effects of thebackscatter in the fiber optic at a detection point. In embodiments ofthe present invention, the interference effects in the backscatter fromthe fiber optic sensor at a detection point may be provided byconfiguring the length of the fiber optic to be shorter than a coherenceof the source producing the beam, by configuring the coherent beam as apulse of the coherent electromagnetic radiation having a pulse durationequivalent to or shorter then a coherence length of the source producingthe pulse of the coherent electromagnetic radiation and/or the like.

In certain aspects of the present invention, because the fiber opticsensor is configured to act as an interferometer, the fiber optic sensoris sensitive enough to detect mechanical waves originating from acousticoccurrences/events in the wellbore, reservoir and/or conduit. Theacoustic events or occurrences may be changes in flow regimes, changesin flow constituents, interactions of solid materials in the wellbore orpipeline or a fluid in the wellbore or pipeline with the fiber opticsensor, the wellbore, a pipeline and/or the like. The mechanical wavesmay interact with the fiber optic sensor and may cause a change in theCRN (due to changes in relative positions of scattering sites in thefiber optic sensor due to the interaction between the mechanical waveand the fiber optic sensor) and, as a result, may be detected. In otheraspects, temperature and pressure changes in the wellbore, reservoirand/or pipeline may change the CRN properties of the fiber optic and maybe monitored and/or detected. The fiber optic sensor may be a bare orsheathed fiber coupled with the wellbore, a lining of the wellbore, apipeline etc. or it may be a bare or sheathed fiber positionedappurtenant to the wellbore, a lining of the wellbore, a pipeline etc.

Some of the embodiments of the present invention provide for using theoptical fiber to acoustically monitor the wellbore, conduit and/orreservoir. More specifically, but not by way of limitation, in oneembodiment of the present invention, one or more optical fibers may bedisposed along the wellbore or the conduit to act as a distributedacoustic sensor. In some embodiments, one or more acoustic transducersmay be coupled along the fiber optic to increase the acousticsensitivity of the fiber optic.

In an embodiment of the present invention, analysis of thedetected/monitored CRN may provide an understanding of conditions in oraround the wellbore and/or the conduit—including but not limited toformation conditions, presence of sand in the wellbore or conduit,gravel packing processes associated with the wellbore, fracturing,treatments occurring in the wellbore or conduit, wellbore integrity,production data, conduit integrity, flow assurance, storage propertiesof carbon dioxide sequestered in a subterranean formation and/or thelike—and/or conditions of materials contained in the wellbore and/or theconduit, such as multiphase analysis, blockages, hydrocarbon flow,hydrocarbon composition and/or the like. Analysis of the CRN may beperformed by theoretical analysis, modeling, experimentation, comparisonwith results from previous operation of the acoustic monitoring system,results from operation of the acoustic monitoring system under knownconditions and/or the like.

In one aspect of the present invention, time of flight measurements of alight pulse along the one or more fiber optic sensors may be used inconjunction with the monitored CRN in the one or more fiber optics todetermine a location in the wellbore or conduit of an acousticoccurrence.

BRIEF DESCRIPTION OF THE DRAWINGS

In the figures, similar components and/or features may have the samereference label. Further, various components of the same type may bedistinguished by following the reference label by a dash and a secondlabel that distinguishes among the similar components. If only the firstreference label is used in the specification, the description isapplicable to any one of the similar components having the same firstreference label irrespective of the second reference label.

The invention will be better understood in the light of the followingdescription of non-limiting and illustrative embodiments, given withreference to the accompanying drawings, in which:

FIG. 1A is a schematic-type illustration of an intervention tool formonitoring a wellbore or reservoir, in accordance with an embodiment ofthe present invention;

FIG. 1B is a schematic-type illustration of a permanent orsemi-permanent system for monitoring a wellbore or reservoir, inaccordance with an embodiment of the present invention;

FIG. 1C is a schematic-type illustration of a system for monitoring apipeline, in accordance with an embodiment of the present invention;

FIG. 2 illustrates an output signal from a system for monitoring areservoir, wellbore or pipeline, in accordance with an embodiment of thepresent invention; and

FIG. 3 is a flow-type illustration of a method of monitoring areservoir, wellbore or pipeline, in accordance with an embodiment of thepresent invention.

DETAILED DESCRIPTION

The ensuing description provides exemplary embodiments only, and is notintended to limit the scope, applicability or configuration of thedisclosure. Rather, the ensuing description of the exemplary embodimentswill provide those skilled in the art with an enabling description forimplementing one or more exemplary embodiments. It being understood thatvarious changes may be made in the function and arrangement of elementswithout departing from the spirit and scope of the invention as setforth in the appended claims.

Specific details are given in the following description to provide athorough understanding of the embodiments. However, it will beunderstood by one of ordinary skill in the art that the embodiments maybe practiced without these specific details. For example, systems,structures, and other components may be shown as components in blockdiagram form in order not to obscure the embodiments in unnecessarydetail. In other instances, well-known processes, techniques, and othermethods may be shown without unnecessary detail in order to avoidobscuring the embodiments.

Also, it is noted that individual embodiments may be described as aprocess which is depicted as a flowchart, a flow diagram, a structurediagram, or a block diagram. Although a flowchart may describe theoperations as a sequential process, many of the operations can beperformed in parallel or concurrently. In addition, the order of theoperations may be re-arranged. Furthermore, any one or more operationsmay not occur in some embodiments. A process is terminated when itsoperations are completed, but could have additional steps not includedin a figure. A process may correspond to a method, a procedure, etc.

Embodiments of the present invention provide systems and methods formonitoring a reservoir, wellbore or a conduit containing and/ortransporting one or more hydrocarbons or carbon dioxide. Morespecifically, but not by way of limitation, embodiments of the presentinvention provide systems and methods in which one or more fiber opticsmay be used as a distributed sensor to simultaneously monitor an entiresection of the reservoir, wellbore and/or pipeline throughout. The oneor more fiber optics may be coupled with the wellbore, a pipe in thewellbore, the pipeline and/or the like to provide for the distributedmonitoring or the one or more fiber optics may be disposed appurtenantto the wellbore, the pipe in the wellbore, the pipeline and/or the liketo provide for the distributed monitoring. In an embodiment of thepresent invention, CRN is generated and monitored in the fiber optic toprovide that the fiber optic acts as an interferometer that mayacoustically monitor the reservoir, wellbore and/or pipeline.

When electromagnetic radiation is transmitted through a fiber optic, aportion of the electromagnetic radiation will be backscattered in thefiber optic by impurities in the fiber, areas of different refractiveindex in the fiber that may be generated in the process of fabricatingthe fiber, interactions with the surfaces of the fiber optic and/orconnections between the fiber and other fibers or components and/or thelike (collectively referred to herein as scattering sites, scatteringlocations, scattering points, scatterers or the like). Thisback-scattered electromagnetic radiation in the fiber optic is commonlytreated as unwanted noise and steps may be taken to reduce suchbackscattering. However, the backscatter may be used in a technique thatis commonly known as Optical Time Domain Reflectometry (“OTDR”).

In OTDR, a fiber optic may be coupled with a narrow-band electromagneticsource, such as a narrow-band laser or the like. The laser may be usedto produce a short pulse of light that is launched into the fiber opticand a fraction of the scattered light that falls within the angularacceptance cone of the fiber in the return direction, i.e., towards thelaser source, may be guided back to the launching end of the fiber as abackscattered signal. The backscattered signal may be used in OTDR toprovide information regarding the integrity/condition of the fiberoptic.

As such, a detector, that may provide for converting electromagneticsignals, such as optical signals, to electrical signals, may be coupledwith the fiber at a location upstream of a portion of the optical fiberbeing used to transmit the electromagnetic radiation. A signal processormay be coupled with the detector and may process the back scatter in theoptical fiber so that the backscatter may be processed to determine theintegrity of the fiber optic downstream of the detector and thecondition of the downstream fiber optic. In this way, OTDR may providefor monitoring the integrity of fiber optics used to transmit data, todetermine operating characteristics of a fiber optic used to transmitdata, to determine locations where a fiber optic has been broken or isnot functioning properly—i.e. for security monitoring or datatransmission assurance, to remotely detect faults in opticaltransmission systems—or to analyze operating characteristics of devices,such as amplifiers etc., associated with the fiber optic.

The fundamentals of OTDR in multimode or single-mode fibers is based onincoherence, i.e., an assumption that, owing to the spectral width ofthe source, the backscatter in the fiber within a spatial resolutioncell will add as intensity. As such, a backscatter waveform generated bythe signal processor in OTDR generally takes the form of a decayingexponential, the slope of which is determined by the attenuation of thefiber.

While OTDR is one type of “noise” in the fiber optic, there is alsoanother type of noise that is commonly referred to as Coherent RayleighNoise (“CRN”). CRN arises when the different electromagnetic radiationsignals traveling in the fiber optic interfere with one another. Assuch, in CRN, the electric field vectors from each of the scatteringpoints in the fiber optic within a spatial resolution region of thefiber optic may add as electric field prior to the square-law detectionthat may occur at a detector. In the electric field vector summation,the phase of the individual electromagnetic signals backscattered bydifferent scattering sites may provide for interference effects that maycreate an interference pattern that may be detected by the detector.

Scattering occurs in optical fibers, as noted above, due to themicroscopic fluctuations in the refractive index of the glass of thefiber. When the coherence length of a source injecting pulses ofcoherent electromagnetic radiation into the fiber approaches the pulselength, interference effects will occur in the backscatter signal. For apulse from a perfectly coherent source, the electric field of a pulse oftemporal width t may be described as a function of distance along thefiber optic. Considering two scattering sites, the intensity of thebackscatter may be determined by the optical phase-separation of the twosites.

As such, correlation of successive backscatter traces from successivepulses provides for identifying changes in the relative location ofscattering sites in the fiber optic. For small changes in the relativelocation of the scattering sites, the overall pattern of the trace ofthe backscatter will remain the same but there will be changes in theintensity of the peaks in the traces. For larger changes in the relativelocations of the scattering locations, the actual pattern of thesuccessive traces will change.

In embodiments of the present invention, CRN may be the dominant noisein the fiber optic. In general, previously, CRN has been treated as anuisance and various methods developed to remove or alleviate the CRNgenerated in a fiber optic cable transmitting coherent electromagneticradiation. (See, e.g., U.S. Pat. No. 6,137,611, “Suppression of CoherentRayleigh Noise in Bidirectional Communication Systems,” to Boivin etal.). However, while CRN may produce noise issues in transmissionsystems, a coherent OTDR is, in effect, a distributed interferometerthat may be sensitive to small changes in scatterer site locations inthe fiber such as may be produced by interactions of acoustic waves withthe fiber optic. Therefore, in an embodiment of the present invention,CRN may be generated and monitored in an optic fiber to provide that theoptical fiber may act as a distributed-acoustic-sensor to monitor areservoir, a wellbores and/or a pipeline.

FIGS. 1A-C are schematic-type illustrations of fiber optic monitorsconfigured for using CRN to monitor a reservoir, wellbore and/or apipeline, in accordance with an embodiment of the present invention.

FIG. 1A illustrates a fiber-optic-distributed-interferometeric tool formonitoring a wellbore or reservoir, in accordance with an embodiment ofthe present invention. In FIG. 1A, thefiber-optic-distributed-interferometeric tool may comprise a fiber optic5 that may be deployed in a wellbore 10. The fiber optic 5 may bedeployed in the wellbore 10 from a spooling device 15 or the like toprovide a tool that may be installed in the wellbore 10 to makemeasurements when and as required. The fiber optic 5 may comprise a partof another wellbore tool and may be coupled with such a tool, may becoupled with a wellbore cable, a slickline, an I-Coil, coiled tubingand/or the like. The I-Coil may comprise a fiber bundle that may weldedand hermetically sealed into a small outer-diameter stainless steeltube, where the outer-diameter maybe of the order of millimeters ortenths of millimeters.

In an embodiment of the present invention, the fiber optic 5 may becoupled with a coherent electromagnetic source 20. The coherentelectromagnetic source 20 may comprise a laser or the like. The coherentelectromagnetic source 20 may be configured to provide that thecoherence length of the coherent electromagnetic source 20 approachesthe spatial resolution of the fiber-optic-distributed-interferometerictool and/or the coherent electromagnetic source 20 may be configured toinject a pulse of coherent electromagnetic radiation into the fiberoptic 5 where the coherence time of the coherent electromagnetic source20 is similar to or longer than the duration of the injected pulse. Insuch configurations, the backscatter generated in the fiber optic 5within a spatial resolution cell will add coherently, wherein thespatial resolution cell comprises a length of the fiber optic 5 forwhich spatial resolution exists. The spatial resolution cell for thefiber-optic-distributed-interferometeric tool may comprise the entirelength of the fiber optic 5 or a portion of the fiber optic 5 dependingupon the coherence length of the coherent electromagnetic source 20and/or the length of a pulse of electromagnetic radiation generated bythe coherent electromagnetic source 20 and injected into the fiber optic5. Within the spatial resolution cell, the fiber optic 5 acts as adistributed interferometer where the backscatter generated fromdifferent scattering locations in the fiber optic 5 may interfereaccording to the phase of the backscatter.

A beam splitter 25 or the like may provide for directing the backscattergenerated in the fiber optic 5 onto a detector 27. The detector 27 maycomprise a photo-detector or the like. The beam splitter 25 may comprisea circulator that may direct radiation from the coherent electromagneticsource 20 into the fiber optic 5 and may receive radiation returned fromthe fiber optic 5 and direct the received radiation into the detector27. The detector 27 may be coupled with a processor 30 that may processan output signal from the detector 27. The detector 27 may detect theintensity of the backscattered radiation input from the beam splitter 25as a function of time and the processor 30 may process this output intoa digital form, a trace and/or the like. The processed output may becommunicated to other systems and/or processors or processing software,stored and/or displayed. The processor 30 may comprise a signalprocessor or the like.

In incoherent OTDR, the backscatter waveform generally takes the form ofa decaying exponential, the slope of which is determined by theattenuation of the fiber. In CRN, as generated within the spatialresolution cell of the fiber-optic-distributed-interferometeric tool ofFIG. 1A, the exponential decay of the backscatter waveform is modulatedby interference effects. The resulting waveform may have a spiky,jagged, appearance where the spikes in the waveform correspond topositions along the fiber where the backscattered signals originatingfrom individual scattering centers are largely in phase and as a resultadd with one another to produce an enhanced output at the detector 27.

If the fiber optic 5 and the source frequency from the coherentelectromagnetic source 20 are stable then the output of the detector 27processed by the processor 30 is static, although random. However, smalllocal perturbations of the fiber optic 5 may alter the relative phasingof the scatterers and, thus change the appearance of the CRN waveform.As such, the fiber-optic-distributed-interferometeric tool ofembodiments of the present invention may be highly sensitive, since thespacing between scatterers needs to be changed by only a fraction of anoptical wavelength in order to radically affect the local interferenceat the detector; hence embodiments of the present invention may providefor acoustic monitoring of a wellbore, a pipeline and/or areas aroundthe wellbore and/or the pipeline including reservoirs that may containhydrocarbons or sequestered carbon dioxide.

In an embodiment of the present invention, a pulse of coherent radiationmay be generated by the coherent electromagnetic source 20 and injectedinto the fiber optic 5 and a first output from the detector 27 may beprocessed by the processor 30. Subsequently, a second pulse of coherentradiation may be generated by the coherent electromagnetic source 20 andinjected into the fiber optic 5 and a second output from the detector 27may be processed by the processor 30. If the fiber optic 5 is stable thefirst and the second output will correspond. However, if the coherentRayleigh backscatter signal processed by the processor 30 changes, thismay indicate that the fiber optic 5 is not stable, i.e. that itstemperature has changed and/or the cable has been elongated orcompressed or the fiber optic 5 has interacted with an acoustic wave.

In one embodiment of the present invention, the light launched into thefiber may take the form of a waveform that may be more complex than asimple pulse. In such embodiments, the more complex waveform maygenerate an interference pattern or the like that may be moreinterpretable, contain more information and/or the like then a system inwhich a simple single pulse is injected into the fiber optic. Merely byway of example, in certain aspects of the present invention, a pair ofmutually coherent pulses each having a slightly different opticalfrequency may be launched into the fiber optic. In such aspects, the useof the pair of mutually coherent pulses may allow the backscatter from aregion separated by the two pulses to interfere, so that a measurementof the optical phase difference accumulated over the region separated bythe two pulses, which may be more easily interpreted than the previouslydescribed single-pulse approach. Equivalently, a compensatinginterferometer, such as a Mach-Zehnder interferometer, placed before theoptical detector may provide a measure of the phase changes in theregion defined by the path-length imbalance of the compensatinginterferometer.

Because of the sensitivity of the CRN signal to the smallest changesrelative locations of scatterers in the fiber optic 5, since the spacingbetween scatterers needs to be changed by only a fraction of an opticalwavelength in order to radically affect the local interference, thefiber-optic-distributed-interferometeric tool of the present inventionmay be used to acoustically monitor the wellbore 10. As such, thefiber-optic-distributed-interferometeric tool of the present inventionmay be used to detect and monitor vibrations/mechanical waves in thewellbore that may be produced by occurrences in a reservoir 35 adjacentto the wellbore 10, by processes occurring in or around the wellbore 10,by changes in fluids flowing in or around the wellbore 10 and/or thelike.

By deploying the fiber-optic-distributed-interferometeric tool of the ofthe present invention listening in a wellbore and looking at theevolution of the noise signatures it may be possible monitor theproduction characteristics of the well as well as the health of many ofthe mechanical tools associated with the well. Additionally, thefiber-optic-distributed-interferometeric tool of the present inventionmay be used as a distributed acoustic sensor that may be deployed in awell as a monitoring system. With regard to production logging, thefiber-optic-distributed-interferometeric tool according to an embodimentof the present invention may provide significant benefits by providingfor tracking events and making measurements along the entire wellboresimultaneously. This may be especially useful for long perioddeployments of the fiber-optic-distributed-interferometeric tool. It mayalso bring benefits in deployment in terms of low cost monitoring inwells where a conventional PL string cannot be deployed (for examplebelow a pump) or would be too expensive.

With regard to acoustic occurrences in a wellbore, there may be aconsiderable range of events which occur in a well that produce acousticperturbations. Multiple fluids and phases (gas bubbles, solids, and someliquid mixtures) may produce recognizable acoustic signatures. This caninclude sound attenuation from foam type mixtures. Further, mechanicalevents can produce sound and vibration. Cavitation also produces sound.Merely by way of example, an embodiment of thefiber-optic-distributed-interferometeric tool of the present inventionmay be used as an acoustic sensor for sand detection purposes in surfaceand down-hole environments. The impact of individual sand grains on suchan acoustic sensor may be distinct and detectable. Thus, acousticsystems in accordance with embodiments of the present invention may beused to qualitatively detect presence of sand in a wellbore. Typicallysand hitting a pipe wall may produce broadband noise in and around a 2to 5 kHz region, which may be distinct from flow noise that may generateassociated noise at a frequency below 100 Hz.

Similarly, acoustic systems in accordance with embodiments of thepresent invention may be coupled with a gravel pack assembly and may beused to detect the sand settling around a screen. In such embodiments,the acoustic signature generated by the CRN may change significantlyduring different parts of the gravel packing processes providing thatthe process may be acoustically monitored.

In some embodiments of the present invention, the processed output fromthe processor 30 may be compared with a reference record. In suchembodiments, new peaks and other changes in the CRN signal level may beindicative of changes in the fiber optic 5. The reference record may bea record of CRN for the fiber-optic-distributed-interferometeric toolwhen the tool is first deployed in the wellbore 10, may be a record ofthe CRN for the fiber-optic-distributed-interferometeric tool when thetool is deployed in the wellbore 10 under known conditions, may be arecord of the CRN for the fiber-optic-distributed-interferometeric toolwhen a process to be monitored has commenced, is at a known processpoint and/or the like, may be a record of the CRN for thefiber-optic-distributed-interferometeric tool in another wellbore underreference conditions, may be a previous record of the CRN for thefiber-optic-distributed-interferometeric tool and/or the like.

In some embodiments of the present invention, theoretical analysis,modeling, experimental analysis or data from previous use of thefiber-optic-distributed-interferometeric tool may be used by theprocessor 30 and/or a secondary processor to analyze CRN signals in thefiber optic 5. In such embodiments, the wellbore 10 may be monitored andCRN signals may be analyzed to determine what events are giving rise todetected CRN signals. In conditions in the wellbore 10 wheretemperatures are not fluctuating and the strain on the fiber optic 5 isconsistent changes in the CRN signal may be analyzed as being due toacoustic interactions with the fiber optic 5. Moreover, in certainaspects, signal processing may provide for removing temperature and/orstrain effects from the CRN output of the fiber optic 5. In someembodiments of the present invention, thefiber-optic-distributed-interferometeric tool may be used in conjunctionwith a distributed temperature sensor (“DTS”).

The time between pulse launch from the coherent electromagnetic source20 into the fiber optic 5 and receipt of a backscattered signal isproportional to the distance along the fiber optic 5 to the source ofthe backscattering. As such, in an embodiment of the present invention,the processor 30 may process the time of flight associated with a changein the CRN signal to determine where along the fiber optic 5 an acousticevent is occurring. Accordingly, in some embodiments of the presentinvention, the duty cycle of the pulses generated by the coherentelectromagnetic source 20 may be greater than their individual roundtrip transit times in the fiber optic 5 so as to obtain an unambiguousreturn signal. Merely by way of example, in certain aspects of thepresent invention, to obtain high spatial resolution, the pulsesinjected in the fiber optic 5 from the coherent electromagnetic source20 may be short in duration (e.g., between a few and tens ofmicroseconds) and high in intensity (e.g., tens of mile-watts peakpower) to provide a good signal to noise ratio.

In some aspects of the present invention, the fiber optic 5 may have anon-reflective end 17 to remove/reduce interference effects of reflectedsignals with the CRN signal. In other aspects of the present invention,one or more transducers, not shown, such as microphones or the like, maybe coupled along the fiber optic 5 to provide for increasing theacoustic sensitivity of the fiber-optic-distributed-interferometerictool.

In yet other aspects of the invention, the distributed nature of thebackscatter may be enhanced by inclusion of weak reflectors within thefibre, such as fibre Bragg gratings, mechanical splices or small bubblesdeliberately introduced in fusion splices. Such a structure may be usedto form an interferometric sensor array. From knowledge of thecharacteristics of such a sensor array or the like, in an embodiment ofthe present invention, changes in coherent Rayleigh noise generated bythe interferometric array may be processed to identify and/or determinea location of acoustic occurrences in a pipeline, reservoir and/orwellbore.

FIG. 1B illustrates a fiber-optic-distributed-interferometer forwellbore or reservoir monitoring, in accordance with an embodiment ofthe present invention. The fiber-optic-distributed-interferometercomprises the fiber optic 5 which may be deployed permanently orsemi-permanently in the wellbore 10. The fiber optic 5 may be coupledwith a cable disposed in the wellbore 10, coupled with a casing 40,coupled with a coiled tubing (not shown), disposed between the casing 45and a face 45 of the earth formation surrounding the wellbore 10,coupled with and/or around equipment disposed in the wellbore 10,disposed in an earth formation and positioned appurtenant to thewellbore 10 and/or the like.

The fiber-optic-distributed-interferometer may be coupled with thecoherent electromagnetic source 20, the detector 27 and the processor 30to provide for monitoring of the wellbore 10 and/or the reservoir 35. Incarbon dioxide sequestration applications, the carbon dioxide may bepumped down the wellbore 10 into the surrounding earth formation and/orthe reservoir 35. In some embodiments of the present invention, thefiber-optic-distributed-interferometer may be used to monitor thestorage of the carbon dioxide in the earth formation and/or thetransportation/transfer of the carbon dioxide through the well to theearth formation.

By permanently deploying the fiber-optic-distributed-interferometericfiber of the present invention in a wellbore and listening to thewellbore and looking at the evolution of the noise signatures, it may bepossible to monitor the production characteristics of the well as wellas the health of many of the mechanical tools associated with the well.Additionally, the fiber-optic-distributed-interferometer of the presentinvention may be used as a permanent or semi-permanent distributedacoustic sensor that may be deployed in a well as a monitoring system.With regard to production logging, thefiber-optic-distributed-interferometeric tool according to an embodimentof the present invention may provide significant benefits by providingfor tracking events and making measurements along the entire wellboresimultaneously. This may be especially useful for long perioddeployments of the fiber-optic-distributed-interferometeric tool. It mayalso bring benefits in deployment in terms of low cost monitoring inwells where a conventional production logging string cannot be deployed(for example below a pump) or would be too expensive.

In one embodiment of the present invention, the fiber optic sensors maybe permanently installed in wellbores at selected locations. In aproducing wellbore, the sensors may continuously or periodically (asprogrammed) provide pressure and/or temperature measurements and/oracoustic detection of flow properties of fluids, such as productionfluids, flowing in the wellbore. Such measurements may be preferablymade for each producing zone in each of the wellbores. To performcertain types of reservoir analyses, it is required to know thetemperature and pressure build rates in the wellbores. This requiresmeasuring temperature and pressure at selected locations downhole overextended time periods after shutting down the well at the surface. Inprior art methods, the well is shut down, a wireline tool is conveyedinto the wellbore and positioned at one location in the wellbore. Thetool continuously measures temperature and pressure and may provideother measurements, such as flow rates. These measurements are thenutilized to perform reservoir analysis, which may include determiningthe extent of the hydrocarbon reserves remaining in a field, flowcharacteristics of the fluid from the producing formation, watercontent, etc. The above described prior art methods do not providecontinuous measurements while the well is producing and require specialwireline tools to be conveyed into the borehole. The present invention,on the other hand, provides in-situ measurements while the well isproducing.

The fluid flow information from each zone may be used to determine theeffectiveness of each producing zone. Decreasing flow rates over timemay indicate problems with the flow control devices, such as screens andsliding sleeves, or clogging of the perforations and rock matrix nearthe wellbore. This information may be used to determine the course ofaction, which may include further opening or closing sliding sleeves toincrease or decrease production rates, remedial work, such as cleaningor reaming operations, shutting down a particular zone, etc. Thetemperature and pressure measurements may be used to continually monitoreach production zone and to update reservoir models. Embodiments of thepresent invention do not require transporting wireline tools to thelocation, something that can be very expensive at offshore locations andwellbores drilled in remote locations. Furthermore, in-situ measurementsin accordance with embodiments of the present invention, and computeddata may be communicated to a central office or the offices of thelogging and reservoir engineers via satellite. This continuousmonitoring of wellbores allows taking relatively quick action, which cansignificantly improve the hydrocarbon production and the life of thewellbore. The above described methods may also be taken fornon-producing zones, to determine the effect of production from variouswellbores on the field in which the wellbores are being drilled.

Regarding the use of the invention in connection with screens and flowcontrol devices, whether in injector or producer wells, these devicesmay frequently contain regions within their mechanical structure wherethe flow is concentrated and deliberately restricted and/or not withinthe main wellbore. In these cases, the profile of the choking point maybe designed, in accordance with an embodiment of the present invention,optionally to include vortex-shedding devices, such as a bluff body inthe flow path or corrugation (or other structure) of the wall of theflow channels within the screen or flow control device. Thesestructures, combined with the distributed (or array) interferometricsensor may provide for generation of a characteristic frequency that maybe directly related to the flow velocity, the geometry of the flowchannel and/or a Strouhal number characteristic of the body. In suchembodiments, this may provide that a measure of the flow in each of thechannels that has been so instrumented may be identifiable from the flowvelocity and/or the time-of-flight to the channel of interest.

Changes in the characteristics of vibration and noise with position inthe well may be correlated qualitatively with changing flow rates andflowing mixture compositions versus position; this is the “permanentproduction logging” concept. Changes in the character of noise andvibration over time may be indicative of changing flow conditions, forexample, gas breakthrough into the well may be signaled by an increasein noise/vibration level at and above the location of the gas entry(with perhaps the resonant features characteristic of bubbles). Further,multiphase flows may produce more noise and vibration than single phaseflows and fast flows may produce more noise/vibration than slower flows,thus they may be acoustically detected in embodiments of the presentinvention.

In a complex multilateral well, the flow noise or vibration measured inthe mother wellbore at the point of entry of each lateral may beindicative of flow from that lateral.

In some embodiments of the present invention, crossing the bubble pointpressure (or dew point pressure for a condensate) may be determinable bythe deployed fiber-optic-distributed-interferometer from the increasedlevels of noise on the two-phase side compared to the single phase. Thisrequires simultaneous measurement of pressure and temperature at thepoint of measurement and a time varying wellbore pressure such as willoccur during well start-up or shut-in. Noise mapping up the productiontubing may allow the point of gas/liquid break-out to be detected, andchanges in this position will be indicative of changing pressure ortemperature, or changing fluid composition.

In gas condensate wells there may be a change in the characteristics offlow noise generated within the formation when liquid condensate isbeing deposited as a trapped bank within the formation. Knowledge ofcondensate bank formation is important to management of the productionfrom the well.

The opportunity of collecting a distributed acoustic log along theentire well may be of high value in the hydrocarbon industry. Bycombining acoustic monitoring results from embodiments of the presentinvention with DTS and/or distributed pressure sensing (“DPS”),uncertainty regarding interpretation of DTS and/or DPS measurements maybe alleviated.

In certain aspects of the present invention, detection of liquidbuild-up in gas wells may be detected. In such gas wells, flow noise maybe different for gas bubbling up through water than for single phase gasflow up the production interval and thus may be acousticallymonitored/detected. Also, the vibration characteristics of a free cable(e.g. a fiber optic slick line) will be different when surrounded bywater than by gas, and thus the presence of the liquid or gas may bedetected. In an embodiment of the present invention, the fibers for DTSand/or DPS and the fiber-optic-distributed-interferometer can be readilydeployed together.

In certain aspects of the present invention, a slickline may be used tocontain the fiber optic and may be used with vortex shedders. The vortexshedders could be discs or spheres with diameters of a few centimetersand may be mounted periodically on the slickline. In such aspects, fluidflows past the vortex shedders, the vortex shedders may cause vortexformation and shedding with consequent generation of flow noise. Thefrequency of vortex shedding is (in single phase flow at least) afunction of the flow rate. As such, an array of vortex shedders used inconjunction with the fiber-optic-distributed-interferometer of thepresent invention may be used as a distributed flow meter.

In some embodiments, the fiber-optic-distributed-interferometer may bedisposed below a pump in the wellbore. In such embodiments, fluidentries may be located and the in-coming fluids may be analyzed from thespatial and spectral characteristics of the flow noise/vibrationdetected by the fiber-optic-distributed-interferometer. Becauserod-pumped well flow is intrinsically unsteady, in certain aspects, thenoise/vibration changes due to the changing flow over the pumping cyclemay be diagnosed to determine entries and/or inflow type.

In some embodiments of the present invention, the optical fiber may bedeployed in a slick line or slick tube geometry used to monitor and tunegas lift valve systems. In other embodiments, downhole monitoring ofnoise and vibration created by a pump in the wellbore may be indicativeof valve wear or other malfunctions.

FIG. 1C illustrates a fiber-optic-distributed-interferometer forpipeline monitoring, in accordance with an embodiment of the presentinvention. The fiber-optic-distributed-interferometer comprises thefiber optic 5 which may be coupled permanently or semi-permanently witha pipeline 50. The pipeline 50 may comprise a conduit or the like fortransporting/containing hydrocarbons and/or carbon dioxide. The fiberoptic 5 may be coupled with the pipeline 50, disposed within thepipeline 50, positioned in an earth formation appurtenant to thepipeline 50, positioned in a material coupled with the pipeline 50and/or the like.

The fiber-optic-distributed-interferometer may be coupled with thecoherent electromagnetic source 20, the detector 27 and the processor 30to provide for monitoring of the pipeline 10 and/or a mixture 55 flowingin the pipeline 50. In certain aspects, the mixture 55 may comprise ahydrocarbon and/or carbon dioxide.

In some embodiments of the present invention, acoustic monitoring mayprovide for detection of growth or formation of a blockage (e.g. wax orhydrate) in a pipe as this may be may be indicated acoustically by anincrease in flow noise/vibration at the location of the blockage.

In some embodiments of the present invention, acoustic monitoring mayprovide for detection of slugs or slug-type flow in a pipeline and/or ahorizontal well. Distributed noise/vibration measurements from thefiber-optic-distributed-interferometer made upstream of a point ofapplication of a control stimulus may be to detect and track the motionof fluid slugs along the well/pipeline so as to get early warning of theimpending arrival of a problem, or a forward indicator that can be usedto drive a slug control system.

FIG. 2 illustrates an output signal from a system for monitoring areservoir, wellbore or pipeline, in accordance with an embodiment of thepresent invention. The output signal shows frequency 60 versus time 70for a CRN measurement obtained from a detector that was attached to afiber optic buried in the ground 1 meter below the surface with a twostroke engine running at 40 Hz at ground level above the fiber. As canbe seen in FIG. 2, a strong signal 75 was produced by the CRN system inaccordance with an embodiment of the present invention illustrating theability of such an embodiment to provide for acoustic monitoring.

FIG. 3 is a flow-type illustration of a method of monitoring areservoir, wellbore or pipeline, in accordance with an embodiment of thepresent invention. In step 110, a fiber optic cable may be introducedinto and/or coupled with a section of a wellbore or a pipeline. Thefiber optic may be introduced into the wellbore or the pipeline as partof a measurement tool, i.e., coupled with a cable, coupled with a pipeand or the like, or it may be coupled directly with the pipeline, acasing of the wellbore, drillpipe, coiled tube and/or the like or it maybe disposed in an earth formation appurtenant to the wellbore orpipeline.

In step 120, a coherent pulse of electromagnetic radiation from anelectromagnetic radiation source is passed along the fiber optic cable.The electromagnetic radiation source may be a laser or the like and thepulse may be generated by gating the output of the electromagneticradiation source. In an embodiment of the present invention, thecoherence length of the electromagnetic radiation source approaches thepulse length and/or the spatial resolution of the fiber optic system toprovide that CRN is developed in a spatial resolution cell of the fiberoptic. By selecting a suitable pulse length and/or source coherence thespatial resolution cell may comprise the entire length of the fiberoptic.

In step 130, backscatter from the transmission of the coherent pulsealong the fiber optic cable may be detected. The backscatter may bedetected from measurements from a detector or the like responsive to theelectromagnetic radiation generated by the electromagnetic radiationsource. The backscatter may be processed into trace, which may befrequency versus time trace or the like, that may contain a plurality ofpeaks corresponding to in-phase backscatter from a plurality ofscattering locations along the fiber optic. A processor/signal anlayzermay be coupled with the detector to generate the trace.

In step 140, a second pulse of electromagnetic radiation from theelectromagnetic radiation source may be injected into the fiber opticand in step 150 backscatter from the second pulse may be detected. Instep 160, the backscatter from the first and/or the second pulse may beanalyzed. Analysis may comprise comparing backscatter from the pulseswith a reference backscatter, comparing the two detected backscatterswith each other, analyzing the backscatter from the two pulses withsignature backscatter from known occurrences and/or the like. In someembodiments, the backscatter collected as a result of passing aplurality of pulses (or electromagnetic input waveforms) down the fiberoptic may be analysed, for example to determine the spectralcharacteristics of the signal at each point of interest. Using aplurality of pulses may provide for estimating/determining a powerspectral density.

In an embodiment of the present invention, because the coherence lengthof the electromagnetic radiation source approaches the pulse length, anychanges in relative locations of backscattering sites will cause changesin the backscatter from the two pulses. Moreover, the relative locationsof scattering sites only have to change fractions of wavelengths tocreate such changes in the backscatter. Therefore, in an embodiment ofthe present invention, an acoustic wave/vibrational in the wellboreand/or the pipeline, which may result from an acoustic occurrence suchas a change in the flow of a fluid in the wellbore and/or the pipeline,operation of a device in the wellbore and/or the pipeline and/or thelike may interact with the fiber optic changing its configuration and asa result changing the backscatter so that the acoustic occurrence may beidentified. Consequently, by monitoring the backscatter in the fiberoptic for successive pulses, sections of the wellbore and/or pipelinemay be monitored. Moreover, from analysis, modeling, theory, priorexperience and/or the like, specific acoustic events may be detected bythe signature they may create in the changing backscatter.

In step 160, the location along the fiber optic of the acoustic eventmay be determined from time-of-flight analysis. In an embodiment of thepresent invention, from the fiber location of the acoustic event, thelocation of the acoustic event in the wellbore, reservoir and/orpipeline may be extrapolated.

The method described in FIG. 3 may provide a method for acousticallymonitoring flows in subsea pipelines and/or wellbores. For example, themethod may provide for acoustically monitoring and/or detecting slugflow and/or blockages in the subsea pipelines and/or wellbores.

In another aspect of the present invention, a pipeline and/or wellboremay be acoustically monitored in accordance with the methods and systemdiscussed above and in conjunction DTS may be used to measuretemperatures at one or more locations along the pipeline and/orwellbore. In such and aspect, a leak in the pipeline and/or wellbore maybe detected by identifying noise and temperature anomalies occurring atthe same location along the pipeline and/or wellbore.

The invention has now been described in detail for the purposes ofclarity and understanding. However, it will be appreciated that certainchanges and modifications may be practiced within the scope of theappended claims.

1. A method for using a fibre optic cable for acoustic monitoring, comprising: transmitting a monitoring signal through the fiber optic cable, wherein the monitoring signal comprises at least one pulse of a coherent beam of electromagnetic radiation and a coherence time of the coherent beam of electromagnetic radiation is equal to or longer than a duration of the at least one pulse; detecting coherent Rayleigh noise generated by the transmission of the coherent beam of radiation through the fiber optic cable; and measuring a phase of the coherent Rayleigh noise; and processing the measured phase of the coherent Rayleigh noise to identify an acoustic occurrence along the fibre optic cable.
 2. The method of claim 1, further comprising: using a time-of-flight of the pulse to identify a location of the acoustic occurrence along the fibre optic cable.
 3. The method of claim 1, wherein: the step of transmitting the monitoring signal through the fiber optic cable comprises transmitting a pair of mutually coherent pulses each having a different optical frequency into the fiber optic cable.
 4. The method of claim 3, wherein: the step of measuring the phase of the coherent Rayleigh noise comprises measuring an optical phase difference between the coherent Rayleigh noise generated by the pair of mutually coherent pulses.
 5. The method of claim 1, wherein the step of measuring a phase of the coherent Rayleigh noise comprises using a compensating interferometer to measure the phase changes in a region defined by a path-length imbalance of the compensating interferometer.
 6. The method of claim 5, wherein the compensating interferometer comprises a Mach-Zehnder interferometer.
 7. The method of claim 1, further comprising: disposing one or more acoustic transducers along the fiber optic cable.
 8. The method of claim 1, further comprising: monitoring temperatures at one or more locations along the fibre optic cable.
 9. The method of claim 1, further comprising: disposing the fibre optic cable in a wellbore; and using the fibre optic cable to acoustically monitor at least one of formation conditions around the wellbore, presence of sand in the wellbore, a gravel packing process associated with the wellbore, fracturing of an earth formation surrounding the wellbore, chemical treatments occurring in the wellbore, wellbore integrity, production data for the wellbore, flow assurance in the wellbore and flow properties of fluids in the wellbore.
 10. The method of claim 1, further comprising: disposing the fibre optic cable in a wellbore or pipeline; and disposing one or more vortex-shedding devices in the wellbore or pipeline
 11. The method of claim 10, further comprising: measuring a frequency of an acoustic output from the vortex-shedding device, wherein the acoustic output is generated by contact between the vortex-shedding device and a fluid flowing in the wellbore or the pipe; and using the measured frequency to determine a velocity of a fluid flow in the wellbore or pipeline.
 12. The method of claim 11, further comprising: using a time of flight measurement to determine a fluid flow rate of the fluid flow in the wellbore or pipeline.
 13. The method of claim 1, further comprising: disposing the fibre optic cable in a wellbore or a pipe; and determining when the identified acoustic occurrence is produced by fluid exiting the wellbore or pipe.
 14. The method of claim 13, further comprising: Using a time of flight to identify where the fluid is exiting the wellbore or the pipe.
 15. A system for acoustic monitoring using a fibre optic cable, comprising: the fiber optic cable; a source of coherent electromagnetic radiation coupled with the fiber optic and configured to inject a pulse of the coherent electromagnetic radiation into the fiber optic; a detector coupled with the fiber optic and configured to detect coherent Rayleigh noise generated in the fiber optic by the pulse of coherent electromagnetic radiation; and a processor coupled with the detector and configured to process an occurrence of an acoustic interaction with the fibre optic cable from a phase of the coherent Rayleigh noise. 